Foamed fluids are used in a variety of applications during the recovery of hydrocarbons from subterranean reservoirs. A foamed fluid is a fluid that includes a base fluid, a foaming agent, and a gas, including but not limited to nitrogen, carbon dioxide, air, methane, and the like. The base fluid may be foamed to reduce the amount of base fluid required, to reduce the amount of fluid loss to the formation, and/or to provide enhanced proppant suspension in fracturing fluids. ‘Foaming agent’ is defined herein to be an agent for facilitating the foaming of a base fluid when gas is mixed therewith.
Foamed fluids may also be used during stimulation operations (e.g. unloading of gas wells) to displace any pre-existing fluid and/or formation fluid present in the wellbore. ‘Pre-existing fluid’ is defined herein as a fluid present in the subterranean reservoir wellbore prior to the introduction of the foaming additive and/or the foamed fluid composition into the subterranean reservoir wellbore. ‘Formation fluid’ is defined herein to be any fluid produced from an oil bearing subterranean formation including but not limited to oil, natural gas, water, and the like. Formation fluids may be considered pre-existing fluids, but pre-existing fluids may not necessarily be a formation fluid. For example, other downhole fluids may be injected into the subterranean reservoir wellbore and are still present in the wellbore when the foaming additive is introduced into the wellbore. Thus, the downhole fluid (e.g. drilling fluid, completion fluid, fracturing fluid, injection fluid, etc.) may be the ‘base fluid’ upon introduction of the foaming additive and gas into the subterranean reservoir wellbore.
The base fluid of a foamed fluid may be a drilling fluid, a completion fluid, a stimulation fluid, a fracturing fluid, an injection fluid, and combinations thereof. Non-limiting examples of the use of such fluids may involve unloading oil or gas wells, enhanced oil recovery operation, heavy oil recovery, a drilling operation, a fracturing operation, pressure pumping, cementing, acidizing or other stimulation operation, and the like.
A non-limiting example of a foamed drilling fluid may be one where the drilling operation requires the drilling fluid to have a low density; for example, the density of the foamed drilling fluid may range from about 2.0 ppg (about 0.24 g/cm3) independently to about 8.0 ppg (about 0.96 g/cm3). Drilling fluids are typically classified according to their base fluid. In water-based fluids, solid particles are suspended in a continuous phase consisting of water or brine. Oil can be emulsified in the water, which is the continuous phase. “Water-based fluid” is used herein to include fluids having an aqueous continuous phase where the aqueous continuous phase can be all water or brine, an oil-in-water emulsion, or an oil-in-brine emulsion. Brine-based fluids, of course are water-based fluids, in which the aqueous component is brine.
Oil-based fluids are the opposite or inverse of water-based fluids. “Oil-based fluid” is used herein to include fluids having a non-aqueous continuous phase where the non-aqueous continuous phase is all oil, a non-aqueous fluid, a water-in-oil emulsion, a water-in-non-aqueous emulsion, a brine-in-oil emulsion, or a brine-in-non-aqueous emulsion. In oil-based fluids, solid particles are suspended in a continuous phase consisting of oil or another non-aqueous fluid. Water or brine can be emulsified in the oil; therefore, the oil is the continuous phase. In oil-based fluids, the oil may consist of any oil or water-immiscible fluid that may include, but is not limited to, diesel, mineral oil, esters, refinery cuts and blends, or alpha-olefins. Oil-based fluid as defined herein may also include synthetic-based fluids or muds (SBMs), which are synthetically produced rather than refined from naturally-occurring materials. Synthetic-based fluids often include, but are not necessarily limited to, olefin oligomers of ethylene, esters made from vegetable fatty acids and alcohols, ethers and polyethers made from alcohols and polyalcohols, paraffinic, or aromatic, hydrocarbons alkyl benzenes, terpenes and other natural products and mixtures of these types.
One type of drilling operation involves cementing where cement is pumped into place in a wellbore. Cementing operations may be used to seal an annulus after a casing string has been run, to seal a lost circulation zone, to set a plug in an existing well from which to push off with directional tools, or to plug a well so that it may be abandoned. Before cementing operations commence, the volume of cement to be placed in the wellbore is determined, as well as the physical properties of the slurry and the set cement needed, including density and viscosity. The drilling fluids may be displaced to place the cement in the wellbore.
In carrying out primary cementing, as well as remedial cementing operations in wellbores, the cement slurries utilized must often be light-weight to prevent excessive hydrostatic pressure from being exerted on subterranean formations penetrated by the wellbore. As a result, a variety of light-weight cement slurries have been developed and used, including foamed cement slurries.
In addition to being light-weight, a foamed cement slurry contains compressed gas, which improves the ability of the slurry to maintain pressure and to prevent the flow of formation fluids into and through the slurry during its transition time, i.e., the time during which the cement slurry changes from a true fluid to a hard set mass. Other surfactants, besides those used as foaming agents, may be used as foam stabilizers for preventing the foam slurries from prematurely separating into slurry and gas components, and may also be added to the slurry. Foamed cement slurries may have low fluid loss properties.
There are a variety of functions and characteristics that are expected of completion fluids. The completion fluid may be placed in a well to facilitate final operations prior to initiation of production. Completion fluids are typically brines, including chlorides, bromides, formates, but may be any non-damaging fluid having proper density and flow characteristics. Suitable salts for forming the brines include, but are not necessarily limited to, sodium chloride, calcium chloride, zinc chloride, potassium chloride, potassium bromide, sodium bromide, calcium bromide, zinc bromide, sodium formate, potassium formate, ammonium formate, cesium formate, and mixtures thereof. Chemical compatibility of the completion fluid with the reservoir formation and fluids can be very important. Chemical additives, such as polymers and surfactants are known in the art for being introduced to the brines used in well servicing fluids for various reasons that include, but are not limited to, increasing viscosity, and increasing the density of the brine.
Servicing fluids, such as remediation fluids, stimulation fluids, workover fluids, and the like, have several functions and characteristics necessary for repairing a damaged well. Such fluids may be used for breaking emulsions already formed and for removing formation damage that may have occurred during the drilling, completion and/or production operations. The terms “remedial operations” and “remediate” are defined herein to include a lowering of the viscosity of gel damage and/or the partial or complete removal of damage of any type from a subterranean formation. Similarly, the term “remediation fluid” is defined herein to include any fluid that may be useful in remedial operations. A stimulation fluid may be a treatment fluid prepared to stimulate, restore, or enhance the productivity of a well, such as fracturing fluids and/or matrix stimulation fluids in one non-limiting example.
Hydraulic fracturing is a type of stimulation operation, which uses pump rate and hydraulic pressure to fracture or crack a subterranean formation in a process for improving the recovery of hydrocarbons from the formation. Once the crack or cracks are made, high permeability proppant relative to the formation permeability is pumped into the fracture to prop open the crack. When the applied pump rates and pressures are reduced or removed from the formation, the crack or fracture cannot close or heal completely because the high permeability proppant keeps the crack open. The propped crack or fracture provides a high permeability path connecting the producing wellbore to a larger formation area to enhance the production of hydrocarbons.
The development of suitable fracturing fluids is a complex art because the fluids must simultaneously meet a number of conditions. For example, they must be stable at high temperatures and/or high pump rates and shear rates that can cause the fluids to degrade and prematurely settle out the proppant before the fracturing operation is complete. Various fluids have been developed, but most commercially used fracturing fluids are aqueous-based liquids that have either been gelled or foamed to better suspend the proppants within the fluid.
An acidizing fluid may be pumped into a wellbore to remove near-well formation damage and/or other substances. An acidizing operation may enhance production by increasing the well radius. Sometimes acidizing is referred to as ‘acid fracturing’ when the operation is performed at pressures above the pressure required to fracture the formation. Acidizing operations may have a foaming additive added thereto for creating a foam diverter to divert the acid to a particular location within the wellbore.
Another type of stimulation operation is one where the oil or gas well is ‘unloaded’. In most gas wells, water and/or condensate is produced along with gas. In mature gas wells, decreasing formation pressures and gas velocities gradually cause the wells to become “loaded” with liquids. Because of the difficulties in treating liquid-loaded wells with higher condensate cuts, operators may use a variety of methods to prevent liquid loading in marginal gas wells.
Unloading an oil or gas well may be necessary when a primary production technique (i.e., use of only the initial formation energy to recover the crude oil), followed by the secondary technique of waterflooding, recovers only a small percentage of the original oil in place present in the formation. The average recovery factor is around 25 to 35% for oil fields and around 70% for gas fields after secondary recovery operations. Gas well production and oil well production systems are generally limited in their production due to the load of oil and water in the flowlines.
Gas lift and/or deliquification of wells may enable wells with liquid loading issues to be returned to continuous flowing status, enhance the flow of a current producing well, restart a well, and combinations thereof. Typically, as the oil and/or gas is produced from the reservoir, the pressure of the reservoir formation decreases and the production declines. In addition, the production of the well may decline over time due to completion issues, and the well may become difficult to restart. A method commonly used to deliquify or ‘unload’ these wells is through the application of chemical foaming agents.
Injection fluids may be used in enhanced oil recovery (EOR) operations, which are sophisticated procedures that use viscous forces and/or interfacial forces to increase the hydrocarbon production, e.g. crude oil, from oil reservoirs. The EOR procedures may actually be initiated at any time after the primary productive life of an oil reservoir when the oil production begins to decline. The efficiency of EOR operations may depend on reservoir temperature, pressure, depth, net pay, permeability, residual oil and water saturations, porosity, fluid properties, such as oil API gravity and viscosity, and the like.
EOR operations are considered a tertiary method of hydrocarbon recovery and may be necessary when the primary and/or secondary recovery operation has left behind a substantial quantity of hydrocarbons in the subterranean formation. Primary methods of oil recovery use the natural energy of the reservoir to produce oil or gas and do not require external fluids or heat as a driving energy. The primary recovery method is followed by the secondary recovery method that involves activities such as infill drilling, pressure maintenance and water injection. Tertiary recovery or EOR methods are used to inject materials into the reservoir that are not normally present in the reservoir.
Secondary methods of oil recovery inject external fluids into the reservoir, such as water/and/or gas, to re-pressurize the reservoir and increase the oil displacement. Tertiary EOR methods include the injection of special fluids, such as chemicals, miscible gases and/or thermal energy. The EOR operations follow the primary operations and target the interplay of capillary and viscous forces within the reservoir. For example, in EOR operations, the energy for producing the remaining hydrocarbons from the subterranean formation may be supplied by the injection of fluids into the formation under pressure through one or more injection wells penetrating the formation, whereby the injection fluids drive the hydrocarbons to one or more producing wells penetrating the formation. EOR operations are typically performed by injecting the fluid through the injection well into the subterranean reservoir to restore formation pressure, improve oil displacement or fluid flow in the reservoir, and the like.
Examples of EOR operations include, but are not necessarily limited to, water-based flooding and gas injection methods. Water-based flooding may also be termed ‘chemical flooding’ if chemicals are added to the water-based injection fluid. Water-based flooding may be or include, polymer flooding, ASP (alkali/surfactant/polymer) flooding, SP (surfactant/polymer) flooding, low salinity water and microbial EOR; gas injection includes immiscible and miscible gas methods, such as carbon dioxide flooding, and the like. “Polymer flooding” comprises the addition of water-soluble polymers, such as polyacrylamide, to the injection fluid in order to increase the viscosity of the injection fluid to allow a better sweep efficiency by the injection fluid to displace hydrocarbons through the formation. The viscosified injection fluid may be less likely to by-pass the hydrocarbons and push the remaining hydrocarbons out of the formation.
The use of foam generated in situ by surfactant-alternating-gas (SAG) injection is described as a substitute for polymer drive in an alkaline/surfactant/polymer (ASP) enhanced oil recovery (EOR) process in R. F. Li, et al., “Foam Mobility Control for Surfactant Enhanced Oil Recovery,” SPE 113910, SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Okla., SPE Journal, March, 2010.
Micellar, alkaline, soap-like substances, and the like may be used to reduce interfacial tension between oil and water in the reservoir and mobilize the oil present within the reservoir; whereas, polymers, such as polyacrylamide or polysaccharide may be employed to improve the mobility ratio and sweep efficiency, which is a measure of the effectiveness of an EOR operation that depends on the volume of the reservoir contacted by the injected fluid.
When performing a polymer-in-solution flooding process, a polymer may increase the viscosity of the water to be closer to that of oil, so that less bypassing or channeling of the floodwater may occur. Said differently, the mobility of the floodwater may be decreased to provide a greater displacement of the flood front. Carbon dioxide (CO2) injection is similar to water flooding, except that carbon dioxide is injected into an oil reservoir instead of water to increase the extraction of oil from the reservoir.
The alkaline/surfactant/polymer (ASP) technique may have a very low concentration of a surfactant to create a low interfacial tension between the trapped oil and the injection fluid/formation water. The alkali/surfactant/polymer present in the injection fluid may then be able to penetrate deeper into the formation and contact the trapped oil globules. The alkali may react with the acidic components of the crude oil to form additional surfactant in-situ to continuously provide ultra-low interfacial tension and free the trapped oil. With the ASP technique, polymer may be used to increase the viscosity of the injection fluid, to minimize channeling, and provide mobility control.
Present foaming technology is very responsive to high salinity; that is, high salinity brines disrupt the ability of the fluid to maintain an effective foam. Thus, it would be advantageous if foaming additives were designed for foamed fluids that can generate a very low interfacial tension, yet are capable of withstanding very high salinity environments.